Various types of solar thermal electric power generation plants either already exist commercially or are in late developmental stages. These plants collect and concentrate solar energy (energy contained in sunlight) and convert the solar energy to thermal energy (heat). The thermal energy is then used to generate electric power.
Even in geographic locations that enjoy substantial, strong sunlight and relatively clear weather year-round, the available sunlight is often not sufficient to generate enough electricity to fully utilize, and maximize the economic investment in, a solar thermal plant. For example, solar thermal plants that lack thermal energy storage capabilities cannot generate electricity during nighttime or on overcast days. In addition, the number of hours of daylight are defined and constrained by season.
Some of these limitations can be overcome or lessened by storing thermal energy produced when sunlight is sufficient and recovering it to generate electricity when sunlight is unavailable or insufficient. The degree to which these limitations can be overcome or lessened, and the degree to which the overall utilization of the plant can be expanded, depend primarily on the amount of thermal storage available to the plant and the size of the solar energy collection field relative to the plant's electricity-generating capacity. Most of the thermal storage approaches that have been commercialized to date involve limited capacities that facilitate storage of thermal energy sufficient to operate the generators for four to six hours (Mills and Morgan, Aursa 2007). However, some studies suggest that it may be possible to store thermal energy for up to 16 hours (Stoddard et al., NREL 2006). This storage capacity allows a solar thermal plant to generate electricity into the late afternoon and evening hours or, at most, overnight, following a day of sufficient sunlight. However, it does not allow a plant to store thermal energy during a sunny season for electricity production during a less sunny season or during successive overcast days, or to continue operation during successive overcast days even in a season of normally strong sunlight.
Current methods of short-term thermal energy storage include steam accumulators, pressurized hot-water tanks, hot oil/rock storage vessels, and molten salt. These methods become costly when used to store more than a few hours worth of the heat needed for medium-size or larger electric power plants. In addition, none of these methods adequately addresses long-term, seasonal storage needs.
Geothermal reservoirs are also used to generate electricity. These reservoirs produce hot liquid brine, steam, or a mixture of brine and steam, depending on conditions in the reservoir, at a well-head or in a flash separator. A small minority of geothermal fields produce superheated “dry” steam, while most produce either hot brine or a combination of liquid brine with some flashed vapor, mostly steam. Because pressurized gaseous streams are ultimately used to drive turbine generators, the mass of produced geothermal fluid that can be used to drive a turbine is determined by the amount of the produced geothermal stream that is flashed into steam. Alternatively, the amount of electrical power that can be generated by a binary fluid geothermal power plant depends on the amount of heat that can be transferred from the produced geothermal stream to the binary fluid.
Geothermal power plants usually have fairly low thermal efficiencies relative to solar thermal plants and most other power plants, because of the lower-temperature fluids produced from most geothermal reservoirs. Even a stream produced from a highly efficient geothermal resource will normally flash steam with a temperature less than 450° F. (232° C.). An optimized steam Rankine-cycle power plant utilizing steam flashed from produced geothermal brine will typically enjoy a thermal efficiency of 25% or less, and such efficiency only applies to heat available in the flashed steam, typically less than a quarter of the total mass of the produced geothermal fluids. For this reason, many geothermal resources that might otherwise be considered potential sites for geothermal electric power production do not have sufficiently high thermal efficiency to result in an economically attractive project. Thus, many geothermal and hydrothermal reservoirs are not developed for electric power generation. The thermal energy otherwise available in such resources remains inaccessible from an economic standpoint and thus remains untapped.
Typically, geothermal power plants are fairly small, with the majority less than 100 MW in generating capacity, as a result of reservoir and other limitations. Despite current limitations in generating capacity, which result from a combination of the limitations of current methods, commercial considerations, and reservoir characteristics, many geothermal reservoirs contain a very large amount of thermal energy that could be extracted if the combination of technological and commercial considerations allowed, especially over a long period of time. The available geothermal heat per square mile of geothermal field associated with a 50° F. (28° C.) temperature change within the field (fluids and rock included) is over 190 trillion BTU per square mile. In an eight-square-mile geothermal structure, the available thermal energy could reach 1500 trillion BTU, the heat-equivalent of 1.5 TCF of natural gas. Thus, geothermal heat sources are potentially very, very large energy sources, if they can be tapped and utilized efficiently. Unfortunately, a substantial majority of these sources do not have the requisite temperatures and hydrothermal flows needed to economically sustain a geothermal power plant over a period of time sufficient to make such a project economically attractive. Thus, methods to efficiently access a greater portion of the immense thermal energy within a broad range of geothermal reservoirs would substantially increase society's ability to harness geothermal resources for electric power generation.
Anderson (1978) attempted to increase the overall efficiency of a geothermal power plant by segregating higher-temperature wells that produce more steam into a high-temperature gathering system and collecting lower-temperature geothermal fluids in a separate gathering system. In the geothermal electric power plant, the higher-temperature thermal energy is transferred by heat exchange into a dual power-fluid cycle, which improves the capability of the plant to efficiently generate electric power. Unfortunately, sizable geothermal reservoirs that are suitable for the segregation process of Anderson are rare, resulting in limited opportunities for the application of this process.
The rate at which heat and/or fluids can be withdrawn from geothermal hydrothermal reservoirs is also limited. If fluids are withdrawn too rapidly, then the pressure of the reservoir will normally drop unless replacement fluid flows to the production wells from elsewhere. Unfortunately, replenishment from deeper hot-water resources is often limited, if present at all, such that fluids flowing into production wells are replenished by colder fluids from the flanks of the reservoir, or are not replenished at all. The rate at which this colder fluid is heated by hot geothermal reservoir rock is limited by the rate of heat conduction through the rock itself. As a result, at high production rates, the reservoir pressure drops relatively rapidly because of incomplete fluid replenishment, and the temperature of the reservoir drops over time as colder fluid migrates to the production wells. The combination of lower reservoir pressure and temperature eventually reduces the fluid production rates and, to an even greater extent, the heat production levels, which in turn reduces the amount of power generated.
Spent geothermal brine has been injected into formations to replenish fluid flows to a production well in a geothermal reservoir. However, the spent geothermal brine is injected a great distance from the production well, for example, at least a mile away from production well, and is estimated to take in excess of 50 to 100 years to migrate back to the production well (NDC 1978). While this approach is acceptable for reducing temperature drops, it is ineffective for controlling the pressure drop in the production zone. However, the injection of spent brine in closer proximity to the production well is considered unacceptable because it would cool the produced fluids, thereby reducing the power-generating capability of the geothermal field.
It has also been suggested that supercritical brine could be used to enhance oil recovery and to create synthetic geothermal reservoirs from oil fields. Specifically, Meksvanh et al. (2006) describes a method for injecting a supercritical brine into porous or permeable geologic structures (e.g., sedimentary rock formations) for the purpose of enhancing oil recovery from oil fields. The resulting synthetic reservoirs can subsequently be used for thermal storage and electricity production. The Meksvanh method uses solar concentrators to heat reservoir brine directly to temperatures exceeding both the critical temperature and the critical pressure of the brine (374° C.; 22 MPa (3204 PSIA)). This process temperature is achievable by means of solar collectors, but at substantial cost. The supercritical brine is passed through the rock formations until equilibrium is reached between the supercritical brine and the rock formation, and until a relatively homogeneous temperature is reached throughout the reservoir. Unfortunately, injecting a supercritical brine into a much cooler geologic rock formation results in a loss of approximately half of the electrical generating capability initially and, therefore, a large loss in power-generating capability. Moreover, although the loss in power-generating capability will be reduced as the supercritical brine and the rock formation approach a state of thermal equilibrium, reaching such a state would take many years in the formations described in Meksvanh. For these reasons, the methods described by Meksvanh are not suitable for short-term solar energy storage or electrical power generation wherein the solar heat injected and stored is recovered and utilized within a short (e.g., one month or less) time frame.
The Meksvanh process also suffers from the problem that injection of heated fluids into porous and permeable rock formations can result in fluid and heat loss due to entrapment in fault blocks or selective transportation out of the injection zone of the reservoir through permeability streaks in the formation. There may also be heat losses to shallower sedimentary zones. There could even be a circulation of reservoir fluids with an influx of brine that together result in a cooling of the injection zone. These effects can further extend the time to reach thermal equilibrium, if it is possible to reach thermal equilibrium at all.
There have also been attempts to use solar energy to “augment” geothermal energy by heating geothermal fluids after they are produced from a reservoir. Rappoport (1978) uses heat-transfer fluids to collect geothermal heat from remote wells, then uses solar collectors to replenish heat lost from these streams in transit and to add heat to the heat-transfer fluid before utilizing the heat in a centralized geothermal power plant. In Meksvanh et al., produced brine from oilfields or other permeable reservoirs is heated to supercritical conditions in solar concentrators. Some of this supercritical brine may be used in a power plant. In both the Rappoport and Meksvanh processes, the radiative heat from solar concentrators is added directly to produced geothermal heat energy and then used for power generation.